Good morning, and thank you for standing by. Welcome to the Enterprise First Quarter Conference Call. I would now like to turn the call over to Randy Burkhalter. Please go ahead, sir.
Thank you, Christy. Good morning, everyone, and welcome to the Enterprise Products conference call to discuss Q1 2019 earnings. Our speakers today will be Jim Teague, Chief Executive Officer and Randy Fowler, President and Chief Financial Officer of Enterprise's General Partner. Other members of our senior management team are also in attendance for the call today. Now during this call, we will make forward looking statements within the meaning of 21E of the Securities Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by the management currently available to Enterprise's management team.
Although management believes that the expectations reflected in such forward looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward looking statements made during the call. And with that, I'll turn the call over to Jim. Thank you, Randy. First, let me express my regrets for missing our Analyst Day.
I would have much rather been with you guys, but 3 broken ribs and unbearable pain kept me away. I was glad, however, that you really got to see the quality of our people, have an appreciation for our culture and hopefully get the message of the promising outlook for our business. Not long ago, there was a research note out titled What Will Drive Investors Back Into Energy Stocks. The report said the answer is show me the cash. In the Q1, Enterprise did its part to show me the cash.
Consistency and execution is critical in all facets of our business. We demonstrated it in the Q1 by completing the conversion of 1 of our Seminole NGL pipelines into crude service. And with initial operations on the Shin Oak pipeline 4 months ahead of schedule. Successful execution also includes our ability to deliver returns on invested capital. We have consistently returned capital to our investors for 20 consecutive years of distribution growth and counting while maintaining healthy coverage.
We call that show me the cash. We also take very seriously that many of our long term investors rely on this income. Our balanced approach of returning capital, maintaining coverage, while conservatively using leverage has provided us the financial flexibility to not only weather the cycles, but continue to grow our business during those cycles. That balanced approach has us well positioned to capitalize on organic growth opportunities without relying on the equity capital markets. We believe this will lead to future growth in DCF per unit, distributions and the value of our equity.
We had an exceptional first quarter with 3 of our 4 business segments reporting higher gross operating margin. We set 5 operational records and 6 financial records and that's on the heels of a strong 2018. Excluding non cash mark to market earnings, gross operating margin, EBITDA and DCF each increased by approximately 18% in the Q1 compared to the Q1 of last year. DCF, excluding nonrecurring items, was a record $1,600,000,000 giving us a healthy one point 7 times distribution coverage for the quarter. We retained $665,000,000 for the Q1 that is available to reinvest in our growth.
This record performance was driven contribution from assets that began operations during the past year, volume growth on existing assets, our marketing group's ability to capture some of the West to East spread opportunities in crude oil and natural gas, which more than offset the effect of weaker gas processing margins and temporary closure of the Houston Ship Channel due to the fire at the ITC terminal. As to capital projects on the supply side, our focus on the Permian continues. We placed the initial phase of our Shin Oak NGL pipeline in service at the end of February and is currently running at 250,000 barrels a day. As I said, we completed the conversion of 1 of our Seminole pipelines from NGL to crude service. We refer to that as Midland to ECHO 2, and it is flowing greater than 200,000 barrels a day.
Note that given its location and interconnects, we will always have flexibility to convert this pipeline back to NGL service depending on the pipeline supply demand balances for crude oil and NGLs in the future. I doubt that anyone else will be able to offer this type of future flexibility to Permian producers and to markets. On the demand side, we expect to complete our LPG dock expansion in the Q3, our IBDH plant at the end of the year and partially initiate service of the ethylene export terminal also in the Q4. We recently completed the restart of 55,000 barrels a day of fractionation capacity at our Shupe and T Bone facilities in South Texas and Louisiana respectively. We expect fractionation On the natural gas, natural gas liquids side, we expect to complete the 3rd processing train at Orla this quarter and Mentone 1 in the Q1 of next year.
Orla 1 and 2 were placed in service last year in a running pool. When all of these facilities are completed, we'll have about 1.6 Bcf a day of natural gas processing capacity and 240,000 barrels a day of liquids production out of the Permian. We are in discussions with customers that could lead to our underwriting 2 more processing trains at Mentone. We also expect to complete the expansions of Front Range and Texas Express NGL pipelines in the Q3. Many of you have seen that we filed permits to construct another crude pipeline out of Midland.
If successful, this would be our Midland to ECHO 3 pipeline. We're quite creative in naming these pipelines. We're receiving serious interest from customers who value Enterprise's ability to provide flow and quality assurance and market choices on our integrated system. This integrated system joins together our pipeline, storage, Houston distribution system and marine terminals, safeguarding quality for both producers and end users by way of uninterrupted delivery from the wellhead to refineries or docks. If we are able to successfully underwrite this 3rd pipeline, we would have a lot of flexibility to convert Midland to ECHO 2 back into NGL service should demand support it.
While on the subject of flow assurance, I want to share with you how we performed during the ITC fire and fog days temporarily limited the traffic on the Houston Ship Channel. None of our upstream customers saw any disruptions while ship channel traffic was impaired. And in fact, some of our facilities were used by the authorities during the event. This is the value that a large integrated company like Enterprise provides. This is also the value of being in the Houston market where we have access to 4,500,000 barrels a day of refining and 300,000,000 barrels of storage.
With our loading capabilities, we made up a significant portion of our vessel backlog in April and how much growth that we see from the Permian and where we see the demand. I think they did a good job explaining that light oil will find a home in petrochemicals and gasoline demand. However, after that, we received a lot of questions about LPG demand. Can the world absorb all the future LPG supply? I know a lot of you have to think about these things and you have to ask these questions.
And Tony and his group do a lot of analysis on these subjects. And if you want a deeper dive, I'm sure I'd be happy to do it during the Q and A. But let me give you my personal perspective. I don't worry about this for one second. The reason, I have a fundamental belief.
Price creates demand just as price creates supply. You can ask Tony about demand growth for propane in India. Despite record LPG exports from the U. S, propane is currently worth 40% of WTI and normal butane at 48%. These are historically low relationships that were not typical during the old days.
I think that's a reference to me. In those days, back in the day, propane always sold at 70% to 75% of crude. At 40% of crude, price will create demand. I want to turn the call over to Randy. Let me say again how proud we are of our performance this quarter and how much we are looking forward to the opportunities we see in 2019.
None of this is possible without the extraordinary efforts and teamwork of our employees. I could go on for an hour about the quality of the people we have here at Enterprise. Our strong results this quarter after the record setting year we had last year is a tribute to their work ethic, their creativity and the teamwork you see within our company. And with that, I'll turn it over to Randy.
Thank you, Jim, and good morning, everyone. Starting off with the income statement for the quarter. Net income attributable to limited partners for the Q1 of 2019 was $1,300,000,000 or $0.57 per unit on a fully diluted basis. This included $96,000,000 or $0.04 per unit in non cash mark to market gains. This represents an 11% increase in earnings per unit after adjusting for the effects of mark to market amounts versus the comparable adjusted EPU in the Q1 2018.
As Jim mentioned, we did report 6 financial records for the Q1, including record adjusted EBITDA of $2,000,000,000 and DCF excluding non recurring items of 1,600,000,000 dollars If we follow the recent sell side theme of converting adjusted EBITDA into distributable cash flow, For the Q1, we made this conversion of EBITDA to DCF at 82% for the quarter. This illustrates the benefits of having lower leverage, lower interest rates and a simple structure, which is very efficient in converting cash flow all the way down to the unitholder level. Cash flow from operations was $1,200,000,000 for both the first quarter of 2019 2018. Of note, cash flow from operations for the Q1 was reduced by 5 $60,000,000 for working capital purposes, and this is compared to a use of 203,000,000 dollars for working capital purposes in the Q1 of last year. In traditional terms, our payout ratio, cash distributions paid to limited partners as a percentage of cash flow from operations was approximately 80% for the Q1 2019.
And if we take a look at the trailing 12 months, which if you would sort of smooths out the noise of working capital since the seasonality, the payout ratio was 62%. Free cash flow was $1,900,000,000 for the trailing 12 months ended March 31, 2019, which increased 89% compared to the trailing months ended March 31, 2018 and is $97,000,000 less than the trailing 12 months for December 31, 2018. And again, some of that due to changes in working capital. We placed approximately $1,900,000,000 of major growth capital projects into service through April of this year, including the initial capacity on the Shin Oak NGL pipeline and the conversion of Seminole into crude service. We have approximately $5,000,000,000 of major capital projects under construction that we expect to come into service between now and the end of 2020.
Our capital investments in the Q1 were $1,200,000,000 which includes $62,000,000 of sustained CapEx. We currently expect growth capital investment for 2019 to be in the range of $3,400,000,000 to $3,800,000,000 and another $350,000,000 for sustaining CapEx. For 2019, we still expect to receive approximately $625,000,000 of cash contributions from business partners and projects that are jointly owned. Moving to our balance sheet. At March 31, 2019, our total debt principal outstanding was $20 Assuming the first call date for our hybrids, the average life of our debt portfolio was 14.1 years.
Assuming the final maturity date for the hybrids, the average life of the debt portfolio was 19 years and the effective average cost of debt was about 4.5%. Adjusted EBITDA for the trailing 12 months, March 31, after adjusting for the partial equity treatment of the hybrid debt securities. On consolidated liquidity, it was approximately $4,700,000,000 at quarter end, which included available borrowing capacity under our credit facilities and unrestricted cash. Moving on to equity issuances and purchases. Enterprise received approximately $43,000,000 in net proceeds from the distribution reinvestment program and the employee unit purchase program during the Q1 of 2019.
The level of the participation in the DRIP program after turning off the discount was less than half of what it was in the prior quarter, which again would have been with respect to the distribution paid out in November 2018, and we anticipate it may come down further at the next reinvestment date. As we continue the transition to equity self funding, we are now evaluating applying the reinvestment of distributions to open market purchases instead of new issuances. During the Q1 of 2019, we repurchased 1.9 1,000,000 units for $51,600,000 or approximately $27.83 per unit, which more than offset the 1,500,000 units issued through the dividend reinvestment plan and the employee unit purchase plan in February 2019. And with that, Randy, I think we're ready
to open it up for questions.
Okay. Thank you, Randy. Before we open the call up to Q and A, I'd like to mention that we've posted some slides on our website as supplemental information with respect to Q1 earnings. They're listed under the caption Presentations in the Investors section of our website. So Christy, we're now ready to take questions from the audience.
We do have a question from Tristan Richardson of SunTrust.
We'd have to say that the 5 beats in a row doesn't go unnoticed. The only thing is you're making our modeling skills not look so great. Just a quick question on your project execution and just pulling forward some of the projects, specifically Midland Deco, presumably that allowed for some beneficial spread exposure. Fast forwarding today, does that capacity start to shift to 3rd party use all at once? Or is that a gradual shift over time?
Yes. So, Tristan, this is Brent Secrest. If you look at Midland to ECHO 1, I want to say contractually, Jay, we're at for the Q1, we were at
$475,000,000 Yes, that's correct, Brent.
Then we'll ramp up. So, 2nd quarter contracts come on, additional contracts come on. And I want to say we peak at 535 in the case of Midland to ECHO 2, starting April 1, that was pipeline was handed over to the committed shipper and that volume is at 205,000 barrels a day.
Helpful. Thanks. And then just similar question on the natural gas side. Do you see more commercial activity for 3rd party or is some of that space that gives you that spread exposure stay throughout the year?
Hi, good morning. It's Brad Motal. I think it's going to stay there for the rest of the year and beyond. And frankly, I've been impressed with the amount of It's kept up its pace, potentially. Okay.
Kept up its pace potentially.
Helpful. Thank you guys very much.
And your next question comes from Jean Ann Sosbury of Bernstein. Good morning. The LPG export arb has really widened recently. Your export expansion should help with that. Can you share if it's mostly sold fixed fee or if you would have material exposure to the arb when that comes on?
Yes, this is Justin Kleiter. Yes, from a spot perspective, you've certainly seen a widening of the arb and that expansion is going to give us access to capitalizing on that wider arb. However, we maintain our focus on our long term strategy of offer competitive rates on the term supply business. So I think as we think long term, we're not going to deviate from that long term strategy of ensuring that we capitalize on the long term supply at competitive rates.
Okay. That makes sense. And then, how do you see Shin Oak capacity ramping between now and the end of the Q3?
This is Doug Hanley. Shin Oak, as Jim mentioned, currently full at its initial capacity 250,000 barrels a day and we'll be bringing on pumps between now and the end of the year, call it another 100,000 barrels a day by the end of Q3.
Okay. That's all for me. Thank you. And our next question comes from T. J.
Schultz of RBC Capital Markets.
Just on the unit buybacks in the quarter, you noted it covered the DRIP and purchase plans. Just anything to read into that as far as strategy on buybacks and maybe this changes if you go to open market purchases? Just any more color on how you view this as opportunistic time on the buybacks?
Yes. TK, frankly, I don't think there's our perspective has changed that much since our analyst meeting 3 weeks ago. I think we're still looking to be opportunistic with the buyback program as we highlighted at Analyst Day, and we're looking at a number of projects in development that frankly we're feeling pretty good about. And so we may need capital needs there. So I think right now we're just, like I said, being very deliberate and keeping our financial flexibility now.
So really no change, just really more opportunistic in approach.
Okay. And then, you have a crude dock in Corpus through the Eagle Ford JV that's coming online. Would you expect any more storage around that as more pipes in the Corpus are complete? And just if you can provide any color on the capacity to load across that dock? Thanks.
You can take that
one. That dock is operational now and we're working with our partner over there to bring that dock into operation. I want to say currently with the air permit, it is the capacity is just shy of 200,000 barrels a day, Jay, At 200,000 barrels a day. So we think it's I think we're on record about this, but we do think there will be opportunities to help clear that market as pipelines come online, docks come on at different times. There is some potential misalignment between pipelines and docs.
So certainly, we're looking for opportunities like that.
Perfect. Thanks.
And your next question comes from Spiro Dounis of Credit Suisse.
Hey, good morning, everyone. First question just on the Permian. Just curious if you're seeing any near term impact on NGL volumes at the Permian as a result of the Waha basis. I think most of the shut ins were on the gassier acreage, but just curious if that's also resulted in any sort of meaningful impact on liquids and processing economics?
This is Brad Motal again. We have not seen any impact from shutting gas relative to our processing volumes on our equity gas plants out in the Permian.
Okay, great. And then I believe you made the comment at the Analyst Day that I think you're seeing or finding it increasingly harder to offer NGL customers transportation without also offering frac and export capability. And just curious if that's resulted in ability to maybe premium prices, just given that you're integrated and obviously differentiated on that front? And then are you able to sort of see that same dynamic either in crude or refined products as well?
Hey, Betty. Hey, this is Brent. I think the ability to offer all of those services is a benefit to enterprise. And I think we're shy about saying that we leverage the integration to offer those type of services. I think the customers that we have the most success with are probably the typically a larger type customer who want to be in that game, they want to be in the export game.
In the case of crude oil, I do think that us having control of that barrel all the way through from the field all the way to the dock when it comes to maintaining quality executing what that producer wants us to do with that barrel. I do think it gives us an advantage. And I think frankly you're seeing it with our volumes are coming on quarter by quarter.
Is it fair to say, Grant, on your on Midland to ECHO 1, I think you have only one contract that doesn't have an associated dock deal with it.
That's right.
And I think that one contract is in
dock deal. That's correct.
So that's evidence that to your point, the bundle service is quite valuable to us.
And our next question comes from Justin Jenkins of Raymond James.
Hey, good morning everybody. I guess maybe thinking about the propylene market, it seemed like that was one of the few headwinds in 1Q. Maybe just your thoughts on how operations unfold here in 2Q and market outlook in the near term for that particular business line?
I'm going to let Chris Deanna jump on that, but I think it was headwinds because last year Q1 we had $0.20 plus spreads retainer grade to polymer grade. That's not something that you would expect long term. I think our spreads were more in the range of what we would have expected. Chris?
Yes, that's absolutely right, Jim. Our Q1 of last year, the spreads were just historically very wide, and we've returned more to a normal. Now our pricing here in the U. S. Is much lower than other regions.
So that's also opened up the
dock.
And I guess maybe follow-up here on the CapEx bump for 2019. Is that an acceleration of existing projects? Or is that a combination of that and maybe some new projects to the fold?
Yes, Bill. And coming in and looking at it, the increase was approximately about $250,000,000 and I'd say almost 60% of that is in projects that are $10,000,000 and less. And then frankly, that's normally where we get our best returns on capital or from those smaller projects.
Perfect. Thanks, guys.
And your next question comes from Christine Cho with Barclays.
Good morning, everyone. In your prepared remarks, you guys talked about the propane price being lower as a percentage of crude than where it's historically been. How much of that is a function of price pressure at Mont Belvieu because it looks like we're at export capacity and with the winter demand domestically for propane going away, more of it I'm sure needs to clear the market.
Do you
expect that we're going to see more pressure on propane and butane until your export expansion comes on?
I think you could see a little more pressure on both of them. And you're right that it's at 40% of crude because the winter is over and there's a lot of supply. I mean you nailed it.
Okay. And then I guess just as a follow-up on your LPG export expansion. What if you are doing contracting, what are the rates and tenure looking like for those contracts versus what you historically assigned on your first round of export capacity?
This is Brent. I think in terms of the it's changed in a sense, I think you're seeing the U. S. Producers step in for these type of contracts. So in the first kind of wave on these, it was traders, it was potentially end users who are trying to open up the U.
S. Market. So they had alternative sources of supply. I think now to go back to your prior question, in the case of HD5 propane, it's got to find somewhere to go. And so it's going to get turned into export quality propane.
So I feel confident on terms of the length. Obviously, we're not going to get the rates that we got the last time around. Frankly, we've been fairly public that that was probably a mistake. And we got we probably asked for too high numbers and we lost our market share. So you're going to see rates that are quite a bit less than we got the first time around.
You'll see a different type of customer for us. But in terms of term, I think we'll see longer term.
And let me say, when Brent says lost our market share, he's talking about going from 80% to 45% to 50%. You can't with all the volume, I don't think we can continue being the only game in town. But the other thing he's saying is we're not going to make the mistake of having prices that invite more competition. People are going to have to compete hard to meet our pricing.
The fact that matter is we have a brownfield project and for us to expand it's much more economical than to allow greenfield projects to start up.
Okay, very helpful. And then can you remind us the hedges like when the hedges that you have on your volumes for Midland to Echo roll off? And should we think that you guys are going to continue to hedge on basin and any uncontracted capacity you have on Midland to ECHO 12?
This is Daniel Boss. The hedges that we have on Midland to ECHO, they primarily roll off towards the end of 2019 and then there's a small portion that goes into 2020. There's about $26,000,000 of gains left on those hedges that will come off mostly in the Q2 Q4 of this year. So beyond that, we're on the capacity that's not contracted under long term agreements, that's pretty wide open.
And should we think that you guys are going to continue to hedge that out?
I think in terms of how we use that space and Brad talked about it and you'll hear potentially Zachary talk about it is we have opportunity with that space And our plan and our methodology is to allow people who are willing to do long term contracts with us to use that space. So we'll try to convert that to long term deals. If we're having a difficult time getting that done, then if we feel like the market is at a number that we like, then we could step in and hedge it. But right now, the focus is to get long term deals.
It's the same thing on the capacity we have on natural gas from Waha to the Gulf Coast. We're taking advantage of it right now, but we plan to leverage it into Mentone III and Mentone IV, right, Brad?
And your next question comes from Keith Stanley of Wolfe Research.
Just some quick clarifications. On crude marketing being so strong in the Q1, is it fair to say most of the year over year increase there is just Seminole ramping up before the contracts kicked in April or were there other areas of strength in crude marketing?
I think if you look at Midland ECHO 2, I want to say we averaged just shy of 100,000 barrels a day on that. That was unhedged space. So that rode the value of what the market was at the time. There is some unhedged space we have on other pipelines. In terms of what you can expect quarter over quarter, I mean, you'll see obviously increased volumes on Seminole.
The rate will probably go down or it will go down, but at the end of the day, that's the highest rate we have on any crude transport out of the Permian Basin. And the fact of the matter is, there will be other opportunities. And it's hard for me to sit there and say the opportunity is going to be at the dock or the opportunity is going to be in storage. But we talk about all the opportunities we have at this company across all the different commodities. In the case of maybe this quarter, there was an opportunity on crude basis.
Okay. That's helpful. And on Frac 10, did Frac 10 get accelerated now, I just want to make sure I'm reading this right, to the Q4 of 2019 instead of early 2020?
Zach, you're too nervous to answer a question?
It did get you started.
It's a nice short answer. Thank you.
And our next question comes from Cole Levine of Tudor, Pickering, Holt.
Thanks. And just to follow-up briefly on the crude oil basis discussion there. To some degree, was Q1 impacted at all by the Cushing to Houston spread? And I guess, if so, when you guys expanded Seaway last year, was there incremental spot capacity associated with that? Or was that all thought of as third party?
Enterprise marketing has seaway space And when the expansion came out last year, that space was fully contracted for. If you look at the Seaway pipeline, the fact that it achieves market based rates, there can be an arb there, but obviously that's shared with our partner. But in the case of volumes, enterprise, the marketing standpoint is moving crude oil down Seaway as it makes sense. And sometimes those volumes are less and sometimes they're more.
Got it. I guess just to circle over to Shin Oak, given last week's update on Alpine High, does that change your view on the ramp over the course of 2019? And if so, is there any potential to backfill that with other counterparties?
This is Doug. No, it doesn't. Just for example, the Shin Oak mainline is in service right now, flowing that 200 and 3,000 barrels a day, and we have yet to complete the lateral down to get those volumes, which would be sometime around June. So we don't see that impacting us. And then furthermore, I believe some of the curtailments or reductions are dry gas, not rich gas.
That's what we're seeing.
The other thing on Shin Oak is the most valuable supply or the most reliable supply to Shin Oak and to our fractionators comes out our own processing plant. And I don't think we're through. We mentioned the possibility of 2 more Mentone plants. I mean, that's another 80,000 barrels a day, Tug. And I don't think that's going to be the end of our processing plants in the Permian, all of which will feed Shin Oak.
And Shin Oak, just a reminder, is not just connected to the Permian, it's connected to our entire system, which touches just about every basin there is.
And your next question is from Shneur Gershuni of UBS.
First off, just wanted to say really appreciate the increased disclosures that you guys disclosed with today's earnings. Just a couple of questions here. Kind of a follow-up on the buyback and the DRIP questions from earlier. Just what are your thoughts on just turning the DRIP completely off at this point right now? And in your responses on buybacks, you talked about wanting to be opportunistic and at the same time, you're evaluating a lot of large projects.
If I recall correctly, at the Analyst Day, you talked about $5,000,000,000 to $10,000,000,000 worth of projects that you were hoping to FID at some point. Is there something more than that, that you're thinking about? Because I mean, your results, Jim, as you said, you showed us the cash, You're producing very healthy excess distributable cash flow that can certainly fund that kind of a backlog. So is there something more that we should be thinking about? Or could we actually see some a more elevated pace of buybacks?
Yes, Shneur, on the DRIP, again, you have some participants in the DRIP that just like to reinvest without broker fees, frankly, and some of that cash is going to continue to come in. Rather than come in and just turn that program off altogether, we could come in and maintain our flexibility by continuing the program. But instead of the units being sourced from newly issued units, you just source the units by doing open market purchases. So I think, 1, I think it still provides the company some flexibility on a longer term basis, but then also comes in and continues to those participants that want to continue to purchase through the DRIP even without a discount, it still keeps that option of a low cost investment option for them. On the as far as being opportunistic on the DRIP, Shneur, really, like I said, not much changed from 3 weeks ago.
I think we still see $5,000,000,000 to $10,000,000,000 worth of projects under development. The guys are continuing to chase other projects as well. And right now, just looking to come in and maintain flexibility and be opportunistic on the buyback. Really not a lot additional perspective
I can give you.
Okay. And maybe as a follow-up question, obviously you're talking about your LPG export capabilities and how strong it is. You have some peers or should I say competitors that are expanding theirs and others that are evaluating it and so forth. Is there an opportunity for you, I'm not sure if the word opportunity is the right word, but just sort of given the competitive landscape, I mean, you kind of want to keep the export capacity to something that's obviously manageable for the market. Do you sort of sit there and say, let's take a lower price on our export fees for a period of time to ensure that all this proposed capacity and potential capacity doesn't actually end up getting built?
Just kind of wondering about your thoughts on the competitive dynamic there.
I think Brent put said it and as did Justin, we're going to be very competitive on long term deals and that translates to we're not going to make the mistake we made last go around. We're not looking at $0.12 fees, we're looking at fees that I doubt people can build greenfield on. Is that right, Justin?
That's right.
All right. I guess that answers the question. Perfect. Thank you very much, guys. Really appreciate the color.
Christy, this is Randy. We have time for one more before we cut the Q and A off, okay?
Yes, sir. And your final question comes from Michael Blum of Wells Fargo.
Thank you. Appreciate it. Good morning, everybody. My questions I have 2 related questions on Midland to ECHO 3. So I guess the first question is, I think consensus view is that within a year, the Permian would be pretty overbuilt in terms of crude takeaway capacity.
So I just wanted to understand in the context of that, is that a bad assumption or what are you seeing that you think you're going to have demand for another incremental crude pipeline out of the Permian? And then the second part of that question is a competitor pipe recently increased the cost pretty substantially of their crude pipe and they pretty much talked about rising steel and labor costs. And so wanted to kind of see what you guys thought in terms of if you're seeing any of that? Thank you.
Hello, Michael. This is Jim. I'll take the first part, later I'll let to Brent and then we'll let Graham answer the last part. But when you have a large producer that wants you to build a pipeline, you take a hard look at it. We differentiate, you see all the pipe coming out of the Permian.
I agree there's a lot of pipe. But there's we differentiate what's going to Corpus, what's going to Cushing as it relates to what's going to Houston. Houston is the big sponge and most of your major producers want to go to Houston and they want to go to the big sponge. And they like the fact that when they come through enterprise, they're going to make sure their quality is going to be we're going to keep the quality high and we're going to give them 4,500,000 barrels a day of market or refining market. We're going to give them 300,000,000 barrels of storage.
We're going to give them the ability to export their barrels. So when we look at, oh, God, there's a lot of pipelines, said there's not enough to Houston. And I think that's what the major producers think.
And I'll add to that, Jim. The fact of the matter is we have a decent number of producers who are coming to us asking us to build another pipeline. And so when I ask you to do that, then obviously you have to take a look at it. And if you look at what we have upstream of our system in Midland and what we have downstream of our system in Houston, When you put everything together, it looks like a really good project. Now, if you want to take out all the production and Tony has his curve and you want to apply the pipeline capacity on there, I would agree with you that it does look overbuilt.
But to Jim's point, so what doesn't happen? And so I think barrels going to Cushing probably don't happen. To apply 100% capacity factor to pipelines that go to Corpus, I think very optimistic. And then if you apply the pipelines that go to Corpus that have acreage dedications, I'm not sure that equals 100% capacity factor. So our contracts, if you look at our contracts and are essentially all 10 year contracts, won't expire until 2026, then we kind of look at that timeframe and find out what's overbuilt.
And at that point in time, it looks like the Permian is underbuilt when it comes to pipeline capacity. Jim alluded to his comments about converting crude oil back to an NGL line that was converted to a crude line back to an NGL line. That's an opportunity. That's an optimization that we have. But ultimately, we don't have any contracts expiring during this overbuilt time.
If we did, I probably would be more concerned about it.
Graham, what about the costs? As far as the costs, we're seeing slight increases in costs from the time we did Midland to ECHO 1, nothing substantial, but I think we've been able to lock in cost for steel and pipe. Steel prices have actually gone down. Pipe stayed relatively flat during that time period just due to the impact of the tariffs, but all that we can do is make a project work for Brent and his team.
Great. Thank you.
Okay, Christy. If you would, would you please give our listeners the replay information before we close the call? Thank you.
Yes, sir. And thank you all for participating in today's conference. This call will be available for replay beginning at 1 o'clock p. M. Eastern Time today through 11:59 p.
M. Eastern Time on May 9, 2019. The conference ID number for the replay is 6,66 7,747. Again, that conference ID for the replay is 6,677,747. The number to dial for the replay is 1-eight hundred-five eighty five-eight thousand three hundred and sixty seven or 855-859-2056 or 404537 3406.
Thank you, Christie, and thank you everyone for joining us today and have a good day. Goodbye now.
And thank you again for attending. You may now disconnect.